Producing subterranean formations penetrated by wellbores are often treated to increase the permeabilities of the formations. One such production stimulation involves fracturing the subterranean formation utilizing a viscous treating fluid. That is, the subterranean formation or producing zone is hydraulically fractured whereby one or more cracks or fractures are created therein.
Hydraulic fracturing is typically accomplished by injecting the viscous treating fluid, which may have a proppant such as sand or other particulate material suspended therein, into the subterranean formation or zone at a rate and pressure sufficient to cause the creation of one or more fractures in the desired zone or formation. The treating fluid must have a sufficiently high viscosity to retain the proppant material in suspension as the treating fluid flows into the created fractures. The proppant material functions to prevent the formed fractures from closing upon reduction of the hydraulic pressure which was applied to create the fracture in the formation or zone whereby conductive channels remain in which produced fluids can readily flow to the wellbore upon completion of the fracturing treatment. There are a number of known treating fluids that may be utilized including water-based liquids containing a gelling agent comprised of a polysaccharide, such as for example guar gum.
Viscous treating fluids used in the hydraulic fracturing of petroleum reservoirs and other applications of viscous treating fluids often require field analysis of the predicted viscosity of the treating fluid as a quality control check and as a parameter useful in designing a fracturing operation or the like. Determining the downhole viscosity of the treating fluid prior to deployment of the treating fluid is desirable. Current commercially available viscometers and heat exchangers all suffer from various problems of lack of readability, lack of accuracy, slow response times, and high cost. More particularly, it is difficult to predict the downhole viscosity of treating fluids having a changing viscosity, such as used in hydraulic fracturing operations. One way to determine downhole viscosity prior to deployment is to wait until the entire volume of treating fluid reaches the desired downhole viscosity, for example, through “batch mixing.” This involves the use of a holding tank and a wait of several minutes. However, today's environment calls for mixing on the fly. Time is critical, and waiting for the treating fluid to reach the downhole viscosity is time consuming, impractical, and uneconomical. Additionally, the holding tank requires cleaning and transportation from the site after the job is complete. Previously, the treating fluid was premixed, requiring cleaning of an even greater number of tanks. Another alternative is to force the treating fluid to become more viscous. However, this generally requires significant energy, and is thus costly. Lastly, viscosity curves can project an expected downhole viscosity based on initial viscosity readings. However, field analysis of treating fluids having a changing viscosity, such as used in hydraulic fracturing operations, is somewhat unreliable using the conventional viscometers. In particular, when the initial viscosity is low, conventional viscometers have a high margin of error. Accurate alternatives for measuring low viscosity are expensive and prone to damage in normal field conditions.